Kosmos Energy Ltd. Common Shares (DE)

Good day, everybody, and welcome to Cosmos Energy's second quarter 2025 conference call. As a reminder, this call today is being recorded. At this time, let me turn the call over to Jamie Buckland, Vice President of Investor Relations at Cosmos Energy.

Thank you, Operator, and thanks to everyone for joining us today. This morning, we issued our second quarter 2025 earnings release. This release and the slide presentation to accompany today's call are available on the Investors page of our website. Joining me on the call today to go through the materials are Andy Ingalls, Chairman and CEO, and Neil Shah, CFO. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors we note in this presentation and in our UK and SEC filings. Please refer to our annual report, stock exchange announcement, and SEC filings for more details. These documents are available on our website. At this time, I will turn the call over to Andy.

Thanks, Jamie, and good morning and afternoon to everyone. Thank you for joining us today for our second quarter results call. I'll start off the call by talking about Cosmos' priorities, reinforcing the key messages I gave last quarter before updating you on progress across the portfolio. Neil will then walk through the financials and the work we've been doing to enhance the resilience of the balance sheet before I wrap up with closing remarks. We'll then open up the call for Q&A. Starting on slide three, as we navigate the ongoing commodity price volatility, our key priorities have not changed. Last quarter, I talked about growing production and reducing costs to prioritize free cash flow while continuing to strengthen our balance sheet. I'm pleased to say we've made good progress this quarter across each of these areas, starting with production. In June, we announced the GIMI floating LNG vessel had achieved commercial operations date, or COD, a key milestone for the GTA project. COD is achieved when LNG production is tested for a period of 72 hours at the annual contracted rate of around 2.45 million tonnes per annum equivalent. The FLNG has a nameplate capacity of around 2.7 million tonnes per annum, and we're targeting reaching that level in the fourth quarter of the year. The project has now lifted 6.5 gross cargoes year-to-date. In Ghana, we're pleased that Drilling on Jubilee has restarted with the first producer well of the 2526 drilling programme now online. Initial gross production from the well is around 10,000 barrels of oil per day, in line with our expectations. We have also optimized the drilling program by accelerating the scheduled rig maintenance to 3Q, which allows us to drill a second producer this year, replacing a previously planned injector. This planned producer well is expected to add further Jubilee production around the end of the year, ahead of four more wells planned in 2026. I'll talk about that alongside 2Q Jubilee production later in the material. In the Gulf of America, the partnership has ruled the Winterfell 4 well with completion operations underway. The well is expected online around the end of the quarter. We are now approaching COSMOS record high production levels with further near-term growth expected as we push GTA towards the SL&G nameplate capacity and bring on more wells at Jubilee and Winterfell. Moving to cost. We focused on three areas and are making good progress across all three. Firstly, on CapEx. CapEx in the first half of 2025 was around $170 million, down around 65% from the first half of 2024, as we come out of a heavy investment period and start to see the benefits of those investments. With a sharp focus on CapEx in 2025, we've reduced our full-year CapEx forecast from around $400 million to around $350 million, with the first half actual supporting this lower forecast as we slow down some longer-term investments. Secondly, on OPEX, the largest opportunity for OPEX reduction is on GTA, and we're seeing OPEX per BOE fall as production ramps up. We're also targeting the refinancing of the GTA FPSO in the second half of the year, and we're working with the operator to explore alternative lower-cost operating models which could further drive down costs across the project. And thirdly, overhead. We remain on track to deliver $25 million of targeted savings by the end of this year, with the full benefit being seen in 2026 and beyond. And finally, the balance sheet, where we continue to prioritize our financial resilience with a focus on cash flow and debt pay down. On liquidity, we're taking steps to address our upcoming debt maturities As part of today's material, we announced we've agreed indicative terms for a term loan of up to $250 million secured against our Gulf of America assets, and we anticipate using the proceeds to repay our 2026 bond maturity. We're also progressing additional financing activities to fund some of our longer-dated maturities. On hedging, we took advantage of higher prices in late 2Q and early 3Q to hedge more 2026 oil production, with 7 million barrels now hedged in 2026. We're looking to hedge around 50% of 2026 production by the end of this year. And finally, on the RBL, to reflect the timing impact of GTA ramp-up costs on leverage, we were granted a waiver from our banks on the debt cover ratio covenant through to March 2026. Neil will talk about all of these in more detail later, but in summary, we're making good progress against our financial objectives. Turning to slide four, which looks at operations for the quarter. Starting with the GTA project in Senegal and Mauritania. Second quarter net production was just over 7,000 barrels of oil equivalent per day, and the partnership lifted 3.5 gross LNG cargoes as previously communicated. As mentioned on the previous slide, the FLNG commercial operations date was achieved in late June. This is an important operational and financial milestone for Cosmos, as it signals the end of us funding the NOC's CapEx on the project. In Ghana, total net production was around 29,100 barrels of oil equivalent per day. GeoWeave gross production of around 55,000 barrels of oil per day was lower than expected in the second quarter, driven by nine days of planned FPSO shutdown, a period of rise or instability following the restart, which has since been addressed, and underperformance of some wells on the eastern side of the field. I'll talk more on the following slides about how the partnership is addressing these issues and the actions being taken to re-establish the full production potential of the fields. As mentioned on the previous slide, the first producer well of the 2526 program was brought online late last month and is performing well. Jubilee gross gas production was around 16,600 barrels of oil equivalent per day in the second quarter. In early June, we announced that we had signed an MOU with the government of Ghana to extend the licenses to 2040. The license extensions are a win-win for the project partners and the government. with partners now planning long-term investments in the fields to maximize value for all stakeholders. We are working with our partners and the government to finalize the documentation targeting completion in the second half of the year. When I met with President Mahama earlier this year, we discussed his desire to reinvigorate the oil and gas sector in Ghana with increased investment in some of the country's most valuable assets. The license extensions on Jubilee in 10 are aligned with that agenda. At 10, gross oil production in the quarter was just under 16,000 barrels of oil per day. In the Gulf of America, net production was around 19,600 barrels of oil equivalent per day at the upper end of guidance, driven by strong performance from the Kodiak and Oddjob fields. At Winterfell, the partnership has drilled the number four well, with completion operations underway, and the well is expected online later this quarter. On Tiberias, we continue to advance the development with our 50-50 partner, Oxy, with FID targeted next year. In actual Guinea, net production was just under 8,000 barrels of oil per day, lower than expectations due to some subsea pump mechanical failures at Sabre. The operator expects the first replacement pump to be installed in the fourth quarter, with production expected to rise thereafter. Turning to slide five. At GTA, we continue to see a lot of positive progress with the project now fully operational. Year-to-date, we've lifted 6.5 gross cargoes, and the cadence of cargo liftings is increasing as production ramps up. Further progress is expected with production expected to rise towards a nameplate capacity of 2.7 million tonnes per annum in the fourth quarter. Production of the project is expected to fluctuate slightly with seasonal temperatures with higher production expected during the winter months when the air and sea temperatures are cooler. Four-year guidance of 20 gross cargoes reflects the slightly slower production ramp-up that we saw in the second quarter and early third quarter. Importantly, the subsurface is performing well, which is a key factor as we plan future expansion phases. As a reminder, there is around 25 TCF of discovered gas in place at GTA. Phase 1 only requires around 3 TCF for 20 years of production at the contracted rate. This is a world-class gas resource with significant running room. The partnership also expects the first condensate cargo late in the third quarter, a meaningful additional revenue stream for the project. On operating costs, both startup and commissioning costs should start to fall away in the second half of the year. We're also progressing the refinance in the FPSO lease, starting completion in the second half of the year. Additionally, the partners are working with the operators to explore alternative lower-cost operating models to drive down costs further. As we look out with Phase 1 now fully operational, the next major opportunity to enhance value is through future expansions. Phase 1+, a low-cost brownfield expansion that leverages the existing Phase 1 infrastructure to enable gas production to double at a fraction of the cost to increase LNG production and domestic gas to our host countries. During an official visit to the U.S. in July, the presidents of Senegal and Mauritania met with President Trump at the White House. President Fay of Senegal spoke positively to President Trump about COSMOS, and our critical role in discovering the GTA field 10 years ago. He also talked about the importance to Senegal of U.S. investment from companies like Cosmos and the joint opportunities that could be created through investment in sectors core to the country's economic growth, such as natural gas. The videos of the meetings are online and worth watching. Turning to slide six, 2025 is an important year for our operations in Ghana as we return to drilling. The timeline on the slide shows the journey we are on to deliver the full potential of the Jubilee field. The first half of 2024 marked the end of the previous three-year drilling campaign, which was done using 4D seismic shot in 2017. At the end of that drilling campaign, Jubilee production peaked above 100,000 barrels of oil per day. In the second half of the year, we saw the start of a 12-month drilling hiatus. resulting in some expected natural decline of the field, which was exacerbated by facility issues that we talked about in detail last year, namely reliability of water injection and power generation. The first half of 2025, the partnership carried out a significant facilities work scope on the FPSO during the scheduled shutdown. While voyage replacement for the first half of the year has been above 100%, Production declines have been higher than anticipated in certain wells on the eastern side of the field, including Jubilee Southeast. Riser-based gas lift was introduced to the eastern side of the field, which has helped to restore and stabilize production, and plans are in place to do the same on the western side of the field in the future. In early 2025, we acquired Mu40 across the field, the first since 2017, to ensure the next set of wells we drill in Jubilee Southeast. are the best targets de-risked with the best data and technology. A key event in the second quarter was the arrival of the rig to commence the 25-26 drilling campaign. In July, we brought the first new well online in over a year, a producer in the Jubilee main reservoir with initial gross production of around 10,000 barrels of oil a day. The 2025 rig program has been optimized to drill a second producer well in the Jubilee main field, following a period of scheduled rig maintenance. The second producer well is expected online around the end of the year. We're excited to see the enhanced imaging of the Fast-Track 4D seismic data now coming through, which we plan to further improve using ocean bottom node seismic, or OBM, which we expect to acquire later in the year. I'll talk more about that on the following slide. As we look forward to next year and beyond, we're back to a more regular drilling cadence with four wells committed in 2026, which will start to benefit from the new seismic. Turning to slide seven, I want to spend some time on this slide talking about the importance of consistent drilling and how the partnership is planning to use the latest technologies to deliver the full potential of Jubilee. Using cutting-edge seismic technology to enhance resource recovery in midlife fields is a growing theme across the industry, with recent communications from some of the majors highlighting the significant role they expect it to play over the coming years. The 4D narrow azimuth seismic, or NAS, shot in the first quarter of the year was the first seismic acquired over the fields since 2017. This new seismic data, processed with the latest technologies, is generating a better understanding of the subsurface through enhanced imaging, which is helping to identify new undrilled lobes and unswept oil. As can be seen on the slide, the modern NAS data on the bottom right shows much greater definition of existing reservoirs and yields an improved understanding of fluid movements over time compared to the legacy seismic in the top right. The improved imaging of the new data also provides greater visibility and understanding of deeper potential. At Cosmos, we've taken the lead in coupling this modern seismic with new AI-enhanced data interpretation and reservoir modeling to maximize recovery. As mentioned on the previous slide, we're planning to acquire OBN data over the field later in the year, which will enhance the velocity model to further uplift the NAS processing. The velocity model inserts to the two images on the slide show the evolution and improvement in clarity from 2017 to the present day, and we think there's more to go with OBM data. The second message on the slide I want to focus on is drilling. We talked at length in the past about the need for regular drilling on Jubilee, a key part of delivering the field's potential, alongside high facility uptime and sustained water injection. As I mentioned, the 2526 drilling program is now underway with the first Jubilee producer, J72, online, and a second Jubilee mainfield producer expected online around the end of the year. Following completion of that well, the rig is scheduled to drill four wells in Jubilee in 2026, targeting well-defined mainfield producers supported by good adjacent well control, similar to J72. Going forward, we expect three to four wells per year will be needed to maximize the field's full potential over a multi-year period and sustain higher production levels. With a license extension MOU, the partnership can now plan on long-term investment in Jubilee, which should also drive a material uplift in 2P reserves. In summary, Jubilee is a big field that we expect will get bigger through regular drilling supported by new imaging and reservoir management technology. Turning to slide eight, the Gulf of America second quarter performance was good, with production at the upper end of guidance helped by strong output from both Oddjob and Kodiak. At Winterfell, the number four well was drilled in the second quarter and is anticipated to come online late 3Q. The well is expected to contribute a net rate of COSMOS of around 1,000 barrels of oil equivalent per day. On our development activity, we, together with Oxy, are continuing to progress Tiberius and outboard Wilcox Discovery, working on improved, lower-cost development plans supported by new OBN seismic that we expect to acquire later in the year. FID would then be targeted for next year. Gettysburg is a discovered resource opportunity we acquired in a previous lease sale in the Norfolk trend. To advance the project, we brought in Shell as a 75% partner and operator and are working alongside them in a joint team to progress a low-cost single-well development that would be tied back to Shell's operated Appomattox platform. That concludes the review of the portfolio, and Neil will now take you through the financials.

Thanks, Andy. Turning now to slide 9, which looks at the quarter in detail. Production was higher sequentially due to GTA coming on, and strong performance in the Gulf of America, partly offset by lower production in Jubilee and Equatorial Guinea. Production did come in lower than guidance, mainly due to the ramp-up timing on GTA, which we communicated in June, and lower Jubilee production in the quarter. With GTA ramped up and the first Jubilee well online in July, current production is approaching record highs, as Andy previously mentioned. With additional wells at Jubilee and Winterfell, the installation of replacement pumps at Saba, and ramp up further of GTA targeting the FLNG nameplate capacity. We expect production to continue to rise quarter over quarter into 2026. OPEX per BOE, as shown on the slide excluding GTA, was higher in the quarter, largely reflecting the 1.10 lifting we expect this year. Since 10 operating costs are booked in the quarter, the cargo is lifted. G&A was lower as we start to see the impact of some of the overhead savings coming through. And finally, CapEx came in under budget due to the timing of activity in the Gulf of America and lower GTA costs in the quarter. As Andy discussed earlier, we have lowered our full-year CapEx guidance to approximately $350 million from $400 million, with 1Q and 2Q CapEx demonstrating we are on track to achieve the lower amount, which we believe is sustainable into 2026. With our CAPEX and NOC funding winding down and production increasing, at current oil prices, we are generating free cash flow. While the timing has been slightly delayed, we remain focused on maximizing cash flow in the near term and reducing the absolute amount of net debt. I also want to mention that while working capital is difficult to predict on a quarterly basis, we do expect a working capital draw in the third quarter to reflect the timing of some payments. Turning to slide 10. As Andy said in his opening remarks, one of the priorities for the company this year is enhancing the resilience of the balance sheet, and we've made progress in several key areas recently. On liquidity, we've agreed indicative terms for a senior secured term loan with an investment-grade counterparty at a cost similar to our existing RBL for up to $250 million, which we would anticipate using to repay the outstanding 2026 unsecured note. This facility would be secured against our assets in the Gulf of America with a final maturity date four years after closing, which is anticipated by the end of the third quarter. The chart on the right shows the pro forma impact of this transaction on our maturity schedule, assuming we fully draw down on the new facility to repay the outstanding 2026 notes. Through the second half of this year, we plan to continue working on accessing additional attractive sources of liquidity to potentially repay some of our other longer-dated maturities. On hedging, we continue to add additional protection against commodity price downside through the back half of the year into 2026. For the remainder of 2025, we have 5 million barrels of oil production hedged with a $62 per barrel floor and a $77 per barrel ceiling. We also took advantage of higher prices in late 2Q and early 3Q to add more hedges for 2026. We now have 7 million barrels of oil hedged next year with a floor of $66 per barrel and a ceiling of $75 per barrel. On CapEx, I talked on the previous slide about reducing full-year guidance to approximately 350 million from 400 million. The chart on the bottom right shows the material drop in quarterly CapEx from last year. with lower levels of CapEx expected to continue as we prioritize free cash flow. Finally, we worked with our banks to amend the debt cover ratio calculation for the RBL, increasing the ratio for the next two scheduled test dates to reflect the timing impact of startup of the GTA project on the backwards-looking leverage calculation. The debt cover ratio will return to the originally agreed level thereafter when full-year revenues from the GTA project are better aligned with operating expenses. So in summary, we remain proactive on improving the balance sheet, raising liquidity, increasing hedging, and reducing costs. And we'll continue to update the market as we make further progress in the second half of this year. With that, I'll hand it back to Andy.

Thanks, Neil. Turning now to slide 11 to conclude today's presentation. As I stated in my opening remarks, our near-term focus is on growing production, reducing costs, and enhancing the resilience of the balance sheet, and we're making good progress in all three areas. As we look beyond the near-term, there's significant scope to add long-term value for our investors through high-quality production and development opportunities across the portfolio. On GTA, we're the first phase now, fully operational. We are focusing our efforts towards reducing costs and doubling production to further drive down unit costs through advancing the low-cost brownfield expansion that leverages the existing infrastructure. In Ghana, Jubilee is a big midlife field with significant reserves yet to be produced, which can be accessed by consistent drilling enabled by new technology and the license extension. In the Gulf of America, a proven basin with significant running room, we continue to advance an attractive portfolio of infrastructure-led exploration and development options in the outboard Wilcox and Norfolk trends that leverage Cosmos' capability. In an equatorial Guinea, our assets should deliver cash flow as we selectively invest in production optimization opportunities. So in summary, Cosmos has a diverse, differentiated portfolio with two pre-reserves to production life of over 20 years, with considerable discovered resource beyond that. The conversion of this discovered resource into high-value reserves and then into production will be done at the right pace in a capital-efficient manner, prioritizing cash flow and the balance sheet in the near term. We look forward to delivering on these near-term objectives which will support long-term value creation for our investors. Thank you. And I'd now like to turn the call over to the operator to open the session for questions.

Thank you. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary... to pick up your handset before pressing the star keys. Our first question is from Charles Mead with Johnson Rice. Please proceed.

Good morning, Andy. Good morning, Neil, and to your whole team there. Andy, I want to ask a question about Jubilee. You've given us a lot of great detail here, and I love all the technical detail. But looking at the story from the top down, You mentioned that in the first half of 24, the field was producing over 100,000 barrels, and a year later, you're down to 55 or let's call it 60 adjusted for downtime. So that 40% decline in a year strikes me as high, maybe anomalously high, but if I look at it from a different way and say, okay, well, you need to drill four new producers every year to keep the field flat, and if those producers come in like your latest one, maybe that 40% annual decline is the slope you're fighting every year. So I wonder if you could comment on whether that's a valid way of looking at it and what you'd add to that picture.

Yeah, thanks, Charles. That's a really good question. When you look at it from the top down, I think you're rightly sort of focused on where we are in 2Q. Not only was the shutdown a little challenge, but we did have the additional issues of the riser instability, which we've ironed out. So you sort of have to look in 2Q in the right context, yeah? But it was also impacted, I think, by higher than expected decline, certainly in some of the wells on the eastern side of the field, in particular Jubilee Southeast. So you go, okay, what are we actually doing about that now? I think we talked in quite a lot of detail in the prepared section of the impact of two things. One is better data. We're really pleased with the uplift we're seeing from the fast-track data in the NAS. And again, you need to remember this is fast-track and very early product. And to me, the uplift is huge in terms of our ability to see better data opportunities in the field, both from un-drilled loads and unswept oil. So you're starting to see now a much clearer picture, and I think we did suffer towards the end of the last drilling campaign from the quality of the data we stated back to 2017. So you've got much better data and then the ability then to improve it further than as to the OPN. I think we're going to see a big uplift in the velocity model. So I think the imaging is only going to become clearer. And then as you rightly say, the second part of the story is how do you harness that improved data? You've got to drill regularly. And when we've said all along that you need to get three to four wells in a year to sort of maintain the production levels. So if you sort of take that and sort of track forward, I think we drilled the first of those wells and brought it online last month, and we're seeing production rising as a result. We hope to get a second well on around by year end, and I think that can push production up to around 70,000 barrels a day. So the drilling is more than offsetting the underlying decline and leading to growth. And then four more wells in 26, we think they're likely going to be producers. And if you think each of those is adding 5,000 to 10,000 barrels a day, you can see your way with the, even with the decline that we're seeing, building up towards that sort of 90,000 barrels a day. So I think that's how you get back to where we need to be. And then you can sort of rinse, repeat because you've got quality data and you're starting to deliver a regular, consistent drilling program targeting high-quality wells. So, you know, yes, you know, 2Q was lower than expectation, you know, and you've sort of done the maths on that. But I think even when you were sort of, you know, you adjust it for the one-offs that were in there, and then you start to look at the performance we're seeing from some of the wells that we're drilling, you know, you can reestablish the potential of the field. but it's going to require the two things we talked about. It's going to require good data, and I think I'm really pleased with what we're seeing with the NAS, and I think the fast-track NAS, it'll only get better with the full product, and then the uplift from the OBN, and then back to a regular drilling program.

Got it. That's great detail, Andy. Thank you. And then on GTA, I think you mentioned in your prepared comments and the slides, and it's also in the press release, talking about exploring different operating models to lower costs. Can you give us a sense of what they might be, or more importantly, what the order of magnitude might be for reducing the cost? And I'm guessing that means an absolute sense, not as a precursor to reducing it on a unit basis.

Absolutely, yeah. It's I think to sort of remember that, you know, GTA has certainly been a major project for us. The startup of a major facility such as this, as an LNG scheme, you know, always comes, I think the first year is always a challenging period because you're building plateau, you're removing those shutdown and commissioning costs and getting to steady state. So I think the first order of business is sort of to deliver that outcome and get to that sort of plateau. And I think, you know, we got COD in June. I think we're holding at those levels now. And, you know, we're producing at the ACQ. So I think, but we know there's more to go. When we look at the individual trains and the optimization that can be done, you know, there's absolutely ability to get to nameplate and beyond. So that's part of the journey in the second half of the year. Then part of the journey in the second half of the year is getting those project and startup costs, commissioning costs out of the system and getting to a lower level, which we think we'll achieve both in the fourth quarter. And then looking beyond that, the conversation with the operator is around a couple of things. We're looking at how we refinance the FPSO in the second half of the year. That will bring a significant benefit to Cosmos and to the NOCs. And then beyond that is how do you reduce the operating costs even lower? And that ultimately, Charles, is about exploring all operating models. At the moment, we have a model which is exclusively BP personnel, both on the FPSO and the hub, are the ways in which you can look at models that are employed elsewhere that ultimately get you to a more competitive position. So those are the things that follow next. So I think there's a lot of opportunity to take cost out, and it isn't simply about moving the volume up. It is fundamentally about attacking the cost base from all of the angles that I've talked about.

That's helpful detail. Thank you. Great. Thanks, Charles.

Our next question is from Matt Smith with Bank of America. Please proceed.

Hi there. Good morning. Good afternoon, everyone. Thanks for all those details so far. Perhaps just have one sort of broad question on CapEx. You know, welcome to see that coming down in the guidance for 2025. I guess my question really is, is that CapEx envelope now well below 400 million, around 350? Is that a sensible CapEx envelope to think about going forward? You referenced, of course, Tiberius. FID potentially next year at some stage, phase one plus on GTA. So just wondering, are you comfortable that you could operate within that 350 going forward, or should we expect you to perhaps need to go above that if you're to progress those projects? And perhaps if I tack on a second one related to that, it is just whether you're seeing any changes momentum on that GTA phase one plus project at the moment, good alignment from the partnership or, you know, how close to near term is progress there? I guess it's the crux of my question, please.

Okay, good. Yeah, Matt, if you look at the, you know, the CapEx relation 400 to 350, it is about really sort of making every dollar count as we look at the investment going into the, into the company and prioritizing the, the free cashflow. So, you know, it is at a lot of, you know, lots of opportunities right across the portfolio. But I'd say the majority has been slowing down some of the longer-term projects, in particular Tiberius. So if you sort of look to the next question, then, is can you sustain the 350 into 26? You know, we haven't given CapEx guidance yet. If you sort of step back and say that the primary call on capital in 26 is the four wells that we've got committed in Jubilee, that's a primary call on CapEx. Actually, in actual guinea, not really any significant CapEx call. On GTL, I'll come on to it in a minute, we don't believe phase one is going to be a significant part of 26. It will follow slightly slower. Therefore, probably the FID of Tiberius will come probably towards the end of the year. So when you take that and you look at the focus on, particularly in the volatile oil price environment that we have today, a forward number of around 350 can be not only sustain the company, but it will grow the company, as I just talked about, through the impact of the Jubilee Wells, without damaging that future growth profile. So I think, you know, it's... you know, in summary, you know, yeah, around 350, probably right. Yes, around 350, the company's going to continue to grow. And then, you know, you have the subsequent follow-on, which is more 27, 28 period, where you would see some spend on Tiberius, some spend on Phase I Plus. Okay? Then on Phase I Plus... The most important thing to start with on that is actually the performance of the subsurface on phase one. We've got three wells online at the moment. They're all performing in line with expectation. So that was a little bit of a gating item amongst the partnership wanting to see the reservoir performance. We're now sort of, you know, we started up right at the end of the year, 31st of December, so we've got essentially more than, you know, sort of seven months of production data and feel good about what we're seeing. So the results are absolutely there in terms of the ability to expand the project. In terms of alignment around the partnership, there is alignment around a brownfield expansion, the ability to double volume, double volume through brownfield expansion of the FPSO, which was designed to do circa double the rate that it's doing today, and the incremental investment to get it there is very small. So alignment around that. Alignment around actually that incremental gas will go into LNG and domestic gas. There's a call from the government for domestic gas equally. The rate at which they ramp up that domestic gas core is one issue that we're working. And then the ability to de-bottling the GIME to provide additional LNG capacity is the other part of the exam question. How do I use that incremental, you know, 300 to 400 million standard cubic feet? So that's the work that we're doing at the moment. So I'd say that, you know, The fundamental issue is, of course, therefore around the number of wells which you need to support that incremental sort of 350. And, you know, good that the reservoir is performing. We're getting track record now. And therefore, I believe we have the opportunity, I think, to sort of really refine that well count. So that's sort of the work that's ongoing at the moment. There are three things. Get the well count right. How many wells do you need? When do you need them? to support the incremental volume, what's the timing of that volume in terms of domestic gas, and what uplift can you see from the GIME to be able to deliver that.

Perfect. Well, thank you, Andy. Happy to pass now.

Great. Thanks.

Our next question is from Bob Brackett with Bernstein Research. Please proceed.

Hey, good morning. I have a clarification maybe and then a question. The clarification follows what Charles had alluded to, a 40% decline in the 100,000 a day Jubilee field. The way I read the release is something more like three to four wells a year to maintain flat performance and maybe those split between producers and injectors. And that gets you to something like a 15 to 20% base decline. Is that the better way to think of it?

Yeah, it is, Bob. Yeah, I think you've described it accurately. So if you think about the near-term program, we're going to heavily weight producers because we believe we've got sufficient injection capacity as you ramp up from where we are today up to that sort of 90,000 barrels of oil per day. So you don't really need today. additional injectors so you can sort of high grade the program to producers but to be able to do that you need a data etc as I talked through with Charles When you're at that higher level, then I think the decline rate that you've talked about is the level in which you can manage the field. And therefore, you will need injectors because you've got a high level of offtake. And therefore, a mix of producers and injectors three to four miles per year is the right way to think about it.

And then I guess my core question is somewhat related. which is on the license extension. You have an MOU. Can you share whether there's any change in the fiscal terms or any work program commitment, or is that still up in the air?

No, what we've said, Bob, is that we've described the intent of the MOU and the dimensions that it covers. It's a win-win, really, for both the government and ourselves. What we're doing is... is there is a decrease in the gas price but there's more volume so we've committed to move the volume up to 130 million standard cubic feet a day with a small discount to the gas price. There is an undertaking to drill up to 20 wells and clearly the number will depend on the emerging opportunity set that we see from the NAS but today we see it as being a positive view that we're getting of the reservoir. No change to the fiscal terms. It's under the existing law. And those are the key elements. So I think for us, the most important part is that you can properly invest in the field to deliver a consistent drilling program where you're continuing to invest in the data. Because I think we can see the uplift from the NASS having sort of not been shooting seismic for almost eight years. You know, we need to get back to a regular program probably every three years where you're shooting that. Probably no need to redo OBM, but we would come back to that given that you calibrated the velocity model. So that's the real win-win from this is that with a greater purview you can invest properly up front to deliver that regular program that we talked about where the data is enabling you to drill the best wells that are available.

Very clear. Thanks for that. Great. Thanks, Bob.

Our next question is from Alexa Petrick with Goldman Sachs. Please proceed.

Hey, good morning, team, and thank you for taking our question. Wanted to ask one question on GTA costs. I think the 3Q guide came in a little higher than our expectations. We just want to get your sense of what's in those costs, how do we think about then 4Q, and then any sense of how we should think about it on a per BOE basis for 2026. Thanks.

Yeah, Neil, do you want to pick that up?

Yeah. Hi, Alexis. So the three components in the GTA cost number are sort of the FLNG toll, the FPSO lease, and the field, just sort of a regular field op-ex. And so the FLNG toll is a bit higher in 2Q, given we had some bonus payments that were payable to GOLAR. That's really normalized on a per MCF basis. It's a little over... and so it should be relatively steady both into the back half of this year and into next year. The FPSO is about $15 million a quarter in terms of operating costs of that lease. And again, I think we're saying we're working on, we said we're working on refinancing that in the second half of this year. That's on track. So you'll see the cost come through, the cost reduction come through when that's complete. And again, that's about a little over a quarter of the operating costs. And then the third one, like I said, is sort of field optics, and that sort of will be flat closer to 3Q to 2Q as we sort of still rationalize some of the startup and commissioning costs, and then you'll see a drop-off in that in terms of the fourth quarter that, again, we anticipate we can hold into 26, and then also looking at the alternative models. And so, again, I think on a per-unit basis, you'll continue to see both sides of the equation improve, both in terms of increasing volume and cost coming down.

Okay, that's helpful. And then just wanted to ask, we recognize right now we're in a period of GTA startup costs, production is ramping, but as we think about getting to a point where we have more normalized volumes and costs come off, any thoughts about how we should think about a normalized free cash flow for the business?

And again, I would say our view on that sort of hasn't changed, which is sort of bring the break-even for the business down to sort of the $50 to $55 per barrel type range. And then, again, the sensitivity, depending on what oil price you're using, is about $100. that rate is what we're targeting across the business on a consistent basis.

Okay, that's helpful. I'll turn it over. Thank you all.

Great. Thanks, Alexa.

Our next question is from Mark Wilson with Jefferies. Please proceed.

Thanks, gents. A couple of questions, please. First, on GTA, thinking ahead to Phase 1 plus Is the most important thing we should be looking for a gas sales agreement, either with Senegal, Mauritania, or with a third party? That's the first question. And then on Jubilee, a lot of commentary and detail in the presentation and some hindsight views, I would say, as well. The question I have going forward, particularly with this new seismic data and the processing of that and the work that needs to be done on the longer term, Should you be operator of that field and is that something we're looking for?

Thank you. Thank you, Mark. On the first question, absolutely. I think I was clear when we talked about it earlier that what we're looking to do is work with a partnership and create a partnership that involves the government to find the right blend now of domestic gas versus increased LNG sales. And so, yes, absolutely, part of that whole optimization is around what level of gas can they take, what's the expected ramp-up, and therefore what would a gas sales contract look like. So absolutely, you put it in terms of the Pacific But in terms of an output we would need is certainly as we move towards FID of that, we would need clarity around what that gas sales would look like. But again, the government's clear about the need, and actually the need in the country is absolutely clear. A growing economy needs to be able to leverage gas, displace higher costs, heavy fuel oil, and therefore there is a real economic gain for all parties here by being able to do that. So I don't believe that is a barrier, but it does absolutely need to be addressed. In terms of your second question, look, we work very closely with TELO, as you know. I think it's a good partnership. I think we each have our individual skills. I think being based in particular, actually being based in the Gulf of America, I think the view of being able to leverage seismic, the processing, the acquisition techniques and so on has been something that we've been able to bring to the partnership. And I think we're working really well with Tolo at the moment to leverage their skills and our skills in this domain to make a difference. So there's no difference between where the companies stand on that. We clearly have the rig locked in. We have six wells in front of us. We're aligned around the well choices and what it's going to take to drive the field forward. So I think that, in response to your question, is the most important thing, that we're aligned and actually, you know, COSMOS is bringing something to the party and clearly so is TELA.

Very good. Thank you for those answers. Great. Thank you, Mark.

Our next question is from Stella Cridge with Barclays. Please proceed.

Hi there. Good afternoon, everyone. Many thanks for all of the updates. I was wondering if I could ask on the debt side. So you mentioned that you're progressing additional financing options. I just wondered if you could talk about the different options that might be available to you, how far out on the curve that you're thinking about in terms of maturities. That would be great. And in the RBL, of course, you do have some requirements to address debt a reasonable amount ahead of time. I just wonder if you could talk about how confident you are in meeting some of those requirements of the lending. That would be good. Thanks.

Yeah. Hi, Phil. I'll take that. Just on the further out maturities, again, I think when we set up the maturity schedule in the past, the goal was to leave a few maturities out there and then repay them with cash flow generated from the business. And again, recognizing that The goal from our perspective is to not just reduce leverage but to reduce the amount of Paying off the bonds and cash flow that's generated makes sense. I think inherently that continues to be part of the plan. The big variable there is around oil prices. With the wobble that we had, vanilla oil prices we thought it was prudent to take off to 26 maturity ahead of time with the refinancing. That gives us a bit of space combined with the other proactive measures that we've taken on the financing side to clear a runway. and in that space of time, again, continue to work in a manner to maximize cash flow for the business so that we can continue reducing debt. Alongside that, we'll continue to look at proactive other alternative attractive sources of capital to see if there's a cost-to-capital advantage to be gained in terms of addressing the 27s and 28 maturities as well. If they're trading at a discount, if we can raise low-cost finance against our assets, there's a cost, there's this capital, there's a return to be earned there. And so the plan is to finish the Gulf facility here this quarter and then continue to evaluate those options and part of that will depend on where things trade. If they continue to trade at a discount, there becomes an opportunity for us to accelerate the net debt reduction through the early retirement of those bonds. So again, I think it'll be an ongoing process of evaluating that. And to your second question, just around the RBL, again, we went through the test comfortably in sort of March. Again, we used an RBL price deck to show both from existing liquidity and cash generated between now and the maturities. that we have sufficient sources to cover the uses. Again, I think, you know, the oil price has moved up and down, but, you know, fundamentally, we're well still above borrowing base price X, and so feel good about sort of the generation, future cash generation from the ability, and especially combined with the facility that we put in the Gulf. You know, we'll have, you know, my expectation is we'll continue to have decent coverage as we pass through those tests on a regular basis.

But for many, thanks for that.

Right. Thanks.

Our next question is a follow-up from Bob Brackett with Bernstein Research. Please proceed.

Great. Thanks for taking the question. Again, this has to do with GTA, and you mentioned a domestic gas component. Can you remind me, is that a pipe to St. Louis, or is that some LNG into regas in, say, the car or something? What's envisioned there?

No, I think the primary source would be actually pipeline gas. So this would be a pipe gas solution rather than LNG to Dakar, although there is an LNG regas facility in Dakar, so you could add incremental volume that way. But I think what we're looking at today, Bob, is a more permanent solution.

Okay, very cool. Thanks for that. Great, thanks.

Since there are no further questions at this time, I would like to bring the call to a close. Thanks to everyone for joining today. You may disconnect your lines at this time, and thank you for your participation.